Stress and corrosion acting alone can reduce the service life of metals. There are circumstances, however, where the combined effects of these two factors is greater than the total of the factors acting alone. Particular practical problems are presented where a metal as in a pipeline is stressed and simultaneously subjected to the action of a corrosive medium such as aqueous hydrogen sulfide. The terms associated with these conditions are sulfide stress cracking (SSC) and hydrogen induced stepwise cracking (HIC). Sulfide stress cracking (SSC) is synonymous with sulfide stress corrosion cracking (SSCC).
In pipelines transporting natural gas, the gas often is accompanied by water, sand H.sub.2 S, CO.sub.2, and other impurities, particularly near the well head; natural gas containing significant concentrations of H.sub.2 S is referred to as sour gas. Efforts are made to dewater the gas and remove hydrogen sulfide before the gas enters the transmission pipeline, but these are not always successful. Hydrogen sulfide dissolved in the water forms a weak acid, which corrodes the metal at the internal surface of the pipe. The presence of CO.sub.2 reduces the pH of the solution to approximately 3, aggravating the corrosion problem and breaking down any protective films that may form during the corrosion reaction. During the corrosion reaction, atomic hydrogen is evolved at the pipe surface, and some of the hydrogen is absorbed by the metal. Depending on the condition of the metal and the concentration of hydrogen absorbed, SSC and/or HIC may occur. A similar situation exists for sour crude oil, which contains similar impurities. Crude oil also contains various impurities, including suspended solids, water, and sulfur. Even after some purification, where water and other impurities are removed, sufficient impurities that are detrimental to the pipeline may remain.
SSC and HIC usually are accompanied by minimal material loss as a result of the corrosion reactions. The problem of HIC typically is manifested by the formation of internal cracks and/or surface blisters, which may link up through the pipe wall and lead to a leak in the line. The cracks and blisters form as the result of a buildup of high hydrogen-gas pressures at internal interfaces in the steel, and no external stress is required for HIC to occur. In contrast, SSC involves the interaction of hydrogen in the steel with stress (residual stress and applied service stress), and can result in the development of a delayed, brittle failure in the line. When sulfide stress cracking (SSC) occurs, the cracking often is associated with welds or localized regions of elevated hardness and residual stress. Both HIC and SSC are serious problems in sour-gas and sour-oil applications; however, the consequences of SSC may be more severe.
The pipeline industry has made various efforts at controlling SSC and HIC in sour service. Sour service is the term commonly used to denote service in the presence of hydrogen sulfide. The most common approaches have been to remove water and hydrogen sulfide from the gas or oil and to use inhibitors in the line, usually by applying with a rubber pig and then replenishing by adding them at various entry points in a batch process. Internal coatings have not been used extensively, presumably because any breach in the coating would lead to accelerated localized corrosion. One method that has met with limited success is the development of steels that form protective films during the corrosion reactions. Typical film-forming alloys contain approximately 0.25 percent Cu; however, when the pH of the environment drops to about 3.5, such as when significant CO.sub.2 is present, the protective film formed by these steels becomes unstable. In addition, the use of low-sulfur steels with inclusion-shape control provides improved resistance to HIC only. A more costly alternative is the use of internal polymeric liners; such liners have been used only to a limited extent.
While removal of water and the use of inhibitors appear to represent the current state of the art in controlling SSC and HIC, there is room for improvement. Some instances of failure in sour environments have occurred when inhibitors reportedly were being used. This experience may indicate that the method of application of the inhibitors provides incomplete coverage of the internal surfaces of the pipeline, possibly as a result of limited dispersion of the inhibitor in the carrier. Also, currently used inhibitors are flammable and/or explosive, and may be highly toxic. Thus, there is a need for a nonflammable, nonexplosive, and nontoxic inhibitor with improved dispersion properties, better adherence to metals, and which will inhibit the corrosion reactions that lead to SSC and HIC in sour service. The present invention appears to satisfy all of these criteria.
Additional background material on corrosion may be found in the book Marine and Offshore Corrosion by Kenneth A. Chandler, Butterworths, London, 1985 and in the book Corrosion Engineering, 2nd Edition by Mars G. Fontana and Norbert D. Greene, McGraw Hill, N.Y., 1978. Paper No. 240, Initiation and Propagation Morphology of Sulfide Stress Corrosion Cracking at Welds in Linepipe Steels, by K. Ume et al, presented at Corrosion 85, The International Corrosion Forum, Mar. 25-29, 1985, Boston, Massachusetts, and Paper No. 160, Sulfide Stress Corrosion Cracking of Linepipe, by M. Kimura et al, presented at Corrosion 86, The International Corrosion Forum, Mar. 17-21, 1986, Houston, Texas, provide updated discussions of sulfide stress cracking in pipelines.